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Pragma is bringing the industry’s first 3D metal printed, ultrahigh expansion bridge plug to market, the Aberdeen-based company said in a press release. Its patented M-Bubble bridge plug has successfully completed final lab testing and is due to begin field trials by the end of 2020. Initially targeted at both the plug-and-abandonment (P&A) sector and water shutoff applications, the first M-Bubble addresses a gap in the market for a lower-cost, fast-turnaround, permanent plugging solution, with a high pressure differential (3,000 psi) capability, the company said. The plug can be set without additional cement to save rig time and “waiting-on-cement” time, which can accumulate significant savings for the operator, especially in deeper, extended-reach wells. It also provides barrier-integrity reassurance when there is the possibility of a poor cement bond or cement channeling occurring on the high side of deviated wells, the company added.
Well abandonment has traditionally not been thought of as a crucial part of a well’s life, though it is as much a part of a well’s life cycle as drilling and production. As such, traditional methods of abandoning a well utilizing cement and bridge plugs are still common practice among most operators throughout the world. Recently, however, operators have been challenged to find more cost-effective ways to abandon wells without jeopardizing the sealing integrity and have begun to look for "alternative" abandonment materials. Materials such as resins have been utilized by some as an alternative, but there have not been any major new developments in well abandonment materials for nearly 100 years. Although cement, bridge plugs and resins have their benefits, there are also limitations to their sealing capabilities. Bridge plugs lack a high expansion ratio required in some wells and rely on elastomers to seal, limiting their ability to seal in damaged tubing or open hole environments. Due to the unique properties of bismuth, plugs can be achieved with an expansion ratio of 3:1 and take the shape of the environment they are being set in. Cement is porous and lacks the ability to block gasses from migrating through it while bismuth has no porosity, making it an ideal material for stoping gas migration. Resins must be squeezed into an area and can take days to fully cure before a seal is created as opposed to bismuth which flows in a a well via gravity and solidifies to create a seal in a few hours. This paper will demonstrate a new way to create gas tight seals during well abandonment, overcoming the limitations of traditional methods and reducing the operator’s liability and potential environmental impact after decommissioning has been completed.
Al-Ajmi, Abdullah (Kuwait Oil Company) | Al-Rushoud, Abdulaziz (Kuwait Oil Company) | Al-Naqa, Faisal (Kuwait Oil Company) | Chouhan, Manoj (Kuwait Oil Company) | Al-Mekhlef, Alanoud (Kuwait Oil Company) | Alasoosy, Fawaz (Baker Hughes) | Albohamad, Dalal (Baker Hughes) | Alshab, Mustafa (Baker Hughes) | Ismail, Maizura (Baker Hughes)
A successful cement job is a crucial element of obtaining and maintaining well integrity and ensuring safe and efficient hydrocarbon production. The success of cementation starts with a full understanding of good parameters such as formation characteristics and depends on a properly designed slurry and spacer system.
The most challenging part of cementing a wellbore is cementing one with a low fracture gradient. There's a high risk of formation breakdowns and hole instability if maximum allowable equivalent circulation densities (ECDs) are exceeded. In addition to severe losses and formation damage, the outcome includes inefficient placement of the cement that warrants time-consuming and costly operations to assure zonal isolation.
In Kuwait, first trial of a new generation of an environmentally friendly enhanced aqueous spacer system was used successfully in a highly deviated well for cementing the production casing covering shale formations. This paper discusses the design of the enhanced aqueous system and its technical features and benefits, which helped improve the cement bond and achieve zonal isolation.
Wang, Kelin (Tarim Oilfield Company of PetroChina) | Liu, Shuang (Tarim Oilfield Company of PetroChina) | Liu, Hongtao (Tarim Oilfield Company of PetroChina) | Zhang, Bo (Tarim Oilfield Company of PetroChina) | Wang, Yan (Tarim Oilfield Company of PetroChina) | Tong, Shikun (China University of Petroleum East China) | Zhang, Hao (Tarim Oilfield Company of PetroChina)
Kuqa Foreland Basin is located in Western China, which has typical HPHT reservoir. The reservoir has 80-146MPa pressure, 120-186℃ temperature, and 5000-8235m depth. Reservoir stimulation is usually necessary to improve production rate due to the low matrix permeability, and maximum pump pressure is up to 136MPa. Considering the high risk of casing collapse and well control during completion, production packer is running in the high density killing mud (1.75-2.3SG). Moreover, it should also satisfy the needs of both fracturing and production operations. These extreme conditions bring serious challenge for the production packer selection and operation. The failures of packer are found in more than 10 wells in the past decade and maximum wellbore intervention time is over 160 days.
To solve the production packer failure, the failure reasons of production packer are divided into three categories by conducting simulation experiment and theory calculation. One is mud precipitation in high temperature, which leads to the blockage of packer piston chamber. Second, the gap between the casing and the packer is only 2.39mm. The rubber is expanded when the fluid friction on the rubber is large enough during the process of killing mud displaced by packer fluid, which may result in the failure of displacement fluid, or even packer setting in advance. Third, the calculated axial force on the packer is lower than the real operation, because it does not consider the additional axial force generated by temperature effect of confined space among multiple packers. As a result, packer selection is not reasonable, resulting in the packer mandrel fracture during fracturing operations.
Based on the major reasons for the production packer failure, some measures were taken. One is to conduct the mud aging test for 7-10 days in the temperature that 10-15℃ above reservoir temperature. The scraping for three times is conducted in the expected setting depth for packer. Second, the displacement flow rate of fluid between packer rubber and casing is controlled under 3m/s. Third, maximum outer diameter of packer is reduced by 2.54mm through redesigning packer structure. Last, the expansion joint is chosen to relieve axial force during multiple-packer fracturing. And the number of shear pin is optimized by balancing packer setting and safety. By taking the above measures, the packer failure problem was effectively controlled and failure ratio is reduced to 2.4% in the 43 wells.
More than one hundred and fifty HPHT wells will be deployed for Kuqa Foreland Basin in the next three years, so the effective control of production packer failures can significantly improve operation efficiency and reduce costs. Meanwhile, these experience and lessons learned from production packer selection and operation may also be useful for the other HPHT gas fields.
Loss circulation is encountered frequently while drilling fractured carbonate reservoirs in specific field. The field practice was attempting to cure losses and if incurable, drill blind to total depth (TD) followed by run and cementing of the liner. The interval from loss zone to liner top was covered by the cement squeezed from liner top. The require time to try to cure the lost circulation zone plus squeezing cement job was approximately 15 days. Several optimization initiatives were implemented to reduce this time to less than seven days.
There were at least eight round trips carried out in different ways by different operators to complete the operation of attempting to cure the losses and a liner top squeeze. The engineering team evaluated this for potential optimization, first to identify whether or not losses need to be attempted to be cured to save the time lost on unsuccessful attempts. Second, to analyze the lessons learnt and build on that optimization strategy to reduce the number of trips Lastly to rework the cement slurry design to reduce the number of attempts to squeeze liner top.
As such a detailed strategy was formulated regarding when and how to cure losses followed by an optimized procedure for liner top squeeze which saves three round trips. Further, the liner top squeeze operations previously took multiple attempts of squeeze before a successful pressure test was achieved. Based on the lessons learnt, the slurry design was optimized from several aspects including, slurry density, rheology, thickening time and the pumping and displacement procedure was created which helped to reduce the number attempts from six to only one. Another optimization implemented was enabling the loggers perform pressure pass for cement evaluation by the utilization of tractor instead of conventional (Tough Logging Conditions) TLC which not only saved time but also depicted better the condition of cement behind liner. Finally, a robust risk assessment encompassing all possible contingencies for expected issues was incorporated.
The optimized liner top squeeze strategy has been implemented at five wells with 100% success, reducing the overall operation time from more than two weeks to less than one week while improving cement quality behind liner to ensure zonal isolation as per requirements.
This paper provides details of how the cement slurry, operations sequence and tools selection were enhanced well by well based on continuous improvement. Since cementing liners across loss circulation intervals exists in most of the carbonate reservoirs worldwide, this paper will help to achieve better zonal isolation in losses environment with lower cost and lesser time.
With an increasing number of wells transitioning to their abandonment stages, associated operational efficiency and cost cutting have become a major focus in the industry. An operator had an objective to permanently abandon an offshore well that was suspended in 2016. The key challenge was to develop a long-term well abandonment solution leaving the completion tubing and gauge cables in the well. All the associated operations had to be completed utilizing a lightweight well intervention vessel.
Traditionally, retrieving the entire 5 ½-in. production tubing during plugging and abandonment operations has added operational complexity and costs and increases the risk of exposure to health, safety, and the environment (HSE) hazards. Alternatively, a sealant technique placing cement through and around the completion tubing with gauge cables in-situ exists. However, this technique is associated with a heightened risk of leak path development over time. Ongoing experimental work suggested that enhancements to the conventional cement sealant systems would be beneficial to improve long-term sealing; thus, an active self-sealing cement system that would seal microannuli or small fissures around the tubing and gauge cables was designed. The set cement sealant characteristics include low Young's modulus to resist failure from wellbore stresses and the ability to regenerate the original seal upon contact with any hydrocarbons that may seep through any isolation defects through the life of the abandoned well. To achieve proper cement placement, advanced fluid simulation software and carefully tailored fluid density and rheology profiles were used.
During the operation, a plug of the self-sealing cement sealant was pumped through the production tubing and squeezed into the perforations to create a permanent barrier across the reservoir section. Next, a mechanical plug was set inside the production tubing to isolate the lower section, and the tubing was perforated to provide access to the A-annulus above; subsequently, a balanced plug of self-sealing cement (SSC) system was spotted above. After 30 hours, the plug passed a 3.4-MPa [500-psi] verification pressure test. The operator estimated the operation saved 2 to 3 days of rig time, valued at approximately GBP 400,000 to 600,000. The operator also avoided the risk of leaving the well on long-term suspension with mechanical plugs while waiting for a rig to complete the isolation, and the operation minimized the number of intervention steps required for abandonment, thereby limiting scope growth.
Operators are constantly looking for ways to increase reliability, improve efficiency, and minimize risks, and therefore, abandonment techniques are evolving. The developed solution is a novel and robust alternative to conventional well abandonment using an advanced cement sealant technology for the first time and an innovative placement technique.
This paper describes a game-changing solution regarding the use of metal expandable annular sealing systems in a high pressure multistage frac well. The design and engineering of this technology resulted in the development of fit-for-purpose equipment that overcame challenges often encountered in a high-pressure stimulation environment. The metal expandable annular sealing system was custom designed in order to provide high expansion that can be set in potentially washed out wellbores. The design included a long multi-element sealing system with built-in redundancy to account for fracturing fluid chemical reaction with the rock behind the seals.
The system is just under 4 meters, complemented with multi-elastomer seals, each delivering full Delta P capability within a washed-out hole up to 6.5". The unique design allows full rotational capabilities during deployment, minimizing operational risks.
The system was run in combination with multi open-close fracturing sleeves and a pressure activated toe sub rated to 10,000 psi for acid fracturing in three zones of a vertical carbonate well – the well was known for its heterogeneity and high reservoir pressure contrast. The use of mechanical packers with short sealing elements would have been challenging and increases the risk of unwanted communication between zones. Successful installations, activation of the sleeves and subsequent hydraulic fracturing were achieved, which enabled operational flexibility, reliable isolation and high expansion benefits. Acid fracturing treatment data from each of the stages were analyzed and used to confirm that the zonal isolation integrity.
This paper includes the challenges of providing zonal isolation with conventional packer designs and details the design, testing and qualification of the solution as well as further design modifications for higher fracturing pressure rating.
Nowadays wells are drilled deeper, hotter, and subjected to higher downhole pressures making it more complex for completion, deployment of production tools, and to maintain long term well integrity. It is evident that the utilization of downhole data is becoming more important, to optimize production, maximize the recoverable reserves, and to preserve the proper structure of the wells, facilitating their full life cycle until decommissioning. The Energy industry is relying on new technologies to reduce the cost of exploration, production, and maintaining the wellbore's structural integrity for the duration of the well-life as well as the reduction of their decommissioning cost.
This paper addresses various new opportunities created by an "integrated" casing/tubing/microsensor technology, and real-time data communication from downhole to the surface. This manuscript will highlight some of the main components of this Novel Autonomous and Wireless Real-time Integrated Monitoring System, which consists of: A smart casing-collar module with an array of various sensors, to monitor casing/cement for the initial state of stress, formation creeping, open annuli and near-wellbore reservoir properties. This information is processed through a short-hop, two-way wireless communication system, for data and command transfer from the casing module to the tubing module, and a wireless power transfer system, to provide power from the tubing-module to the casing-module. An intelligent tubing module deployed near the smart casing-collar module that contains another set of smart sensors for production and annulus monitoring. Interfacing with the casing module is done via the short-hop wireless power transfer and communications system. Included here is a downhole power generator and a real-time wireless communication for data transfer to surface. This provides the end user, the ability of in-situ power generation and real-time wireless data.
A smart casing-collar module with an array of various sensors, to monitor casing/cement for the initial state of stress, formation creeping, open annuli and near-wellbore reservoir properties. This information is processed through a short-hop, two-way wireless communication system, for data and command transfer from the casing module to the tubing module, and a wireless power transfer system, to provide power from the tubing-module to the casing-module.
An intelligent tubing module deployed near the smart casing-collar module that contains another set of smart sensors for production and annulus monitoring. Interfacing with the casing module is done via the short-hop wireless power transfer and communications system. Included here is a downhole power generator and a real-time wireless communication for data transfer to surface. This provides the end user, the ability of in-situ power generation and real-time wireless data.
The abovementioned integrated system is aimed at addressing the entire well-life planning needs, as it can feed the asset management system for production optimization, zonal isolation, P&A placement, casing integrity, formation creeping, reservoir evaluation, and potential decommissioning requirements. Custom-specified systems can quickly adapt and incrporate new features that are of potential benefit to other "industries".
Openhole multistage fracturing (OH MSF) completions consisting of openhole packers and ball-activated sleeves have become common to maximize reservoir contact in carbonate formations in Saudi Arabia. However, multiple cases have experienced communication between stages while performing acid fracturing treatments, caused by leaks at the openhole isolation packers. Consequently, sizeable portions of the target reservoir remain unstimulated.
The loss of isolation between stages can be detected during ball landing, followed by an injection test in the subsequent zone. When treating pressure remains essentially the same as before, and after landing the stage ball, the treating fluid is likely bypassing the openhole packer into the previously stimulated interval. To solve this problem, a small volume of fluid carrying degradable multimodal particles and fibers have been pumped at a low rate ahead of the acid fracturing treatment to stop fluid flowing behind the packers. Subsequent treating fluids are injected into the intended interval, thus evenly stimulating the entire lateral.
It was observed that when the pill arrived at the leak, pressure built rapidly, indicating effective bridging of the concentrated particulate pill. The total pressure increase was evaluated to confirm the performance of the pill material and that stage isolation had been restored. Afterward, pressure behavior during the acid fracturing treatments indicated that a new fracture was created in the target openhole interval. In several cases, the pill sustained more than 5,600-psi pressure buildup to successfully plug the leaks. Also, all materials used to form the pill are fully degradable, and no damage is left in the formation. Therefore, the entire wellbore is effectively stimulated with improved reservoir contact, resulting in higher production rates and enhanced reservoir drainage.
Degradable particulate diverters have been widely used in recent years as an effective way to increase stimulated rock volume by diverting at the fracturing face in the near-wellbore region. The cases described in this paper show the first application of this technology as temporary isolation to mitigate interstage communication inside the wellbore.
Tong, Zheng (Research Institute of Petroleum Exploration & Development RIPED, PetroChina) | Liu, Shun (ChangQing Oilfield Company, PetroChina) | Zhang, Weiping (Research Institute of Petroleum Exploration & Development RIPED, PetroChina) | Ye, Qinyou (Jinlin Oilfield Company, PetroChina) | Liao, Chenglong (Research Institute of Petroleum Exploration & Development RIPED, PetroChina) | Qian, Jie (Research Institute of Petroleum Exploration & Development RIPED, PetroChina)
Most 5 1/2in-casing mature wells need to be re-fractured for improving the ultimate recovery. Over the last decade, operators focused on the sidetracking well completion for maximizing wellbore contact. Acid fracturing tend to be performed to treat the reservoirs and make fractures system more complicated as much as possible. The irregularity of slim hole has negative influence on the deploying of completion or fracturing assembly. Isolation tools are usually subjected to heavy corrosion caused by acid or proppant fluid.
The 3 1/2in Open-hole packer-sleeve (OHPS) completion assembly including improved external casing packer (ECP) were proposed for sidetracking well completion. The water-swellable packers (WSPs) with anti-corrosive thermo-plastic vulcanizates (TPVs) was used as the alternative to current mechanical-set ECPs. The TPV matrix was prepared by physically blending high-strengthen carboxylated nitrile (XNBR) with polyamide (PA6). To improve the swelling performance, newly-developed Porous Super Absorbent Resin (PSAR) was mixed and distributed into XNBR/PA6 system. The new swellable TPV exhibits the advantages of high strength, anti-corrosive property and high reliability over traditional packing materials. The TPV material characterization and annular sealing test of 3 1/2in prototype was conducted in the lab.
One 5 1/2in mature oil well was selected for field validation. One 3 1/2in OHPS string with four stages was successfully tripped into large-deviated slim borehole. During the stimulating operation, WSPs acted as effective barriers and any communications between stages did not occurred. It is concluded that the new OHPS using improved WSPs meet requirements of slim-hole sidetracking well completion and stimulation.